1. Field of the Invention
The present invention relates to methods of opening cased well perforations to fluid flow using a treating fluid and perforation sealers.
2. Description of the Prior Art
To protect against collapse and to facilitate various downhole processes, a well (e.g., an oil well, a gas well, an injection well, a water well, etc.) is usually cased. Typically, the casing is cemented in place and extends through one or more producing underground formations. In order to place the cased well in fluid communication with producing formations, the casing must be perforated. Casings can be perforated with round holes using jet perforators, bullet perforators, or other equipment used in the art. Depending upon the diameter of the holes and the size of the casing, a vertical foot of casing can be perforated with up to 30.sup.+ holes.
After the casing perforations have been formed, the well is typically subjected to a breakdown treatment in order to open the perforations to fluid flow. In the breakdown treatment, a treating fluid is pumped into the well under high pressure. Typically, the treating fluid is pumped into the well through a string of tubing positioned inside the casing. The high pressure treating fluid breaks down (i.e., opens up) the casing perforations. The treating fluid then flows through the broken down perforations and into the formation.
Depending on the type of well (e.g., oil, gas, injection, water, etc.) being treated, various types of breakdown fluids are commonly used in the art. Examples include water, brine, oil, foams, emulsions, and like fluids. Additives such as acids, viscosifiers, surfactants, breakers, biocides, fluid loss agents, and the like can be added to the treating fluid in order to enhance the effectiveness of the breakdown treatment.
In order to increase the number of perforations which are successfully broken down during a breakdown treatment, perforation sealers are placed in the treating fluid. In a given formation, the breakdown pressures of the individual perforations can vary substantially. Some perforations break down at a relatively low pressure while other perforations will not break down unless the pressure is much higher. At a constant treating fluid flow rate, perforation sealers operate to increase the treatment pressure by temporarily sealing off perforations which have already broken down. If a constant treating fluid flow rate is maintained, the sealing of one or more of these open perforations forces a greater amount of treating fluid to flow through the broken down perforations which have not yet been sealed. Thus, the pressure within the casing rises as each broken down perforation is sealed.
Typically, the perforation sealers used in breakdown treatments are spherically-shaped, have a diameter slightly greater than the diameter of the casing perforations, and are slightly heavier (i.e., more dense) than the particular treating fluid being used. Ball sealers are generally available in sizes ranging in diameter from about 5/8 inch to about 11/4 inches. Casing perforations, on the other hand, are commonly formed in sizes ranging in diameter from about 3/8 inch to about 7/8 inch. Ball sealers typically have a core composed of a resinous material such as nylon, syntactic foam, or like material and a deformable cover composed of a plastic, an elastomer, rubber, or like material. Perfpac Balls sold by Halliburton Services are particularly well suited for use in breakdown treatments. Perfpac Balls are described, for example, in Data Sheet F-3242 entitled "Halliburton Services-Fracturing Technical Data: Perfpac Balls" published by Halliburton Services, Duncan, Oklahoma 73536, the entire disclosure of which is incorporated herein by reference.
Breakdown treatments are commonly performed using a constant treating fluid flow rate. When a constant treating fluid flow rate is used, a sudden significant decrease in well pressure indicates that at least one additional perforation has broken down. A sudden significant increase in well pressure, on the other hand, indicates that at least one of the broken down perforations has been successfully sealed. Thus, the progress of a constant flow breakdown treatment can be monitored by simply observing the pressure changes which occur at the wellhead (i.e., at the surface entrance to the well).
Although constant flow breakdown treating methods allow simplified monitoring, constant flow breakdown treatments typically must be ended well before all of the broken down perforations have been sealed. As explained hereinabove, when a constant flow rate treatment is used, the pressure in the well casing increases each time a broken down perforation is successfully sealed. These pressure increases promote the breakdown of additional perforations. However, due to large frictional pressure losses in the well tubing, the pressure at the wellhead usually reaches the maximum safe wellhead pressure (MSWHP) before all of the broken down perforations have been sealed. When this point is reached, the sealing of one additional perforation will cause the wellhead pressure to exceed MSWHP. Thus, the treatment must be ended.
Unless substantially all of the broken down perforations have been sealed, optimum breakdown conditions cannot be achieved downhole (i.e., in the perforated zone) and, therefore, many high breakdown pressure perforations will not be opened up. Optimum breakdown conditions exist downhole when the wellhead pressure reaches MSWHP and the tubing frictional pressure loss is essentially zero. If some of the broken down perforations remain unsealed, however, a substantial amount of the high pressure treating fluid continues to flow through the well tubing and out of the unsealed perforations. Thus, the tubing frictional pressure loss remains quite high.
Although some in the art reduced the treating fluid flow rate when the wellhead pressure approaches MSWHP, this technique can also leave many perforations unopened. Since ball sealing efficiency is directly related to the velocity at which the treating fluid flows through the broken down perforations, inadequate perforation sealing can occur when the treating fluid flow rate is reduced. Additionally, even though the flow rate has been reduced, the treatment might still be ended before all of the existing broken down perforations have been sealed. Depending on the number of unsealed perforations and/or poorly sealed perforations existing at the end of the treatment, a substantial amount of the high pressure treating fluid can continue to flow through the well tubing and into the formation. Thus, due to a resulting inability to minimize frictional pressure loss in the well tubing, optimum treating conditions cannot be achieved downhole.
Therefore, a need exists for a reliable, high efficiency breakdown method which overcomes the problems discussed above.